HOUSTON, Feb. 27, 2017 /PRNewswire/ --
- Exceeds High-end of Fourth Quarter and Full Year 2016 Crude Oil
Production Targets
- Beats Fourth Quarter and Full Year 2016 Targets for Lease and
Well, Transportation and DD&A Expenses
- Achieves Record Capital Efficiency Gains in 2016
- Replaces 163 Percent of 2016 Production at Low Finding Cost of
$5.22/Boe (Excluding Price Revisions)
and Increases Total Net Proved Reserves by 1.4 Percent in 2016
- Targets 18 Percent Crude Oil Production Growth for 2017 within
Cash Flow at Flat $50 Oil
- Forecasts Flat to Lower Well Costs in 2017
EOG Resources, Inc. (NYSE: EOG) (EOG) today reported a fourth
quarter 2016 net loss of $142.4
million, or $0.25 per share.
This compares to a fourth quarter 2015 net loss of $284.3 million, or $0.52 per share. For full year 2016,
EOG reported a net loss of $1.1
billion, or $1.98 per share,
compared to a net loss of $4.5
billion, or $8.29 per share,
for the full year 2015.
Adjusted non-GAAP net loss for the fourth quarter 2016 was
$6.7 million, or $0.01 per share, compared to adjusted non-GAAP
net loss of $149.5 million, or
$0.27 per share, for the same prior
year period. Adjusted non-GAAP net loss for the full year
2016 was $892.6 million, or
$1.61 per share, compared to adjusted
non-GAAP net income of $33.9 million,
or $0.06 per share, for the full year
2015. Adjusted non-GAAP net income (loss) is calculated by
matching hedge realizations to settlement months and making certain
other adjustments in order to exclude non-recurring and certain
other items. For a reconciliation of non-GAAP measures to
GAAP measures, please refer to the attached tables.
Higher crude oil, NGL and natural gas prices, significant well
productivity improvements, and lease and well cost reductions
resulted in increases in adjusted non-GAAP net income,
discretionary cash flow and EBITDAX for the fourth quarter 2016
compared to the fourth quarter 2015. For a reconciliation of
non-GAAP measures to GAAP measures, please refer to the attached
tables.
Operational Highlights
Tremendous capital efficiency
improvements in 2016 offset the impact of a significant reduction
in capital expenditures resulting from low oil prices. 2016
total company crude oil and condensate volumes declined less than
one percent to 282,500 barrels of oil per day (Bopd) while
exploration and development expenditures (excluding acquisitions)
decreased 42 percent compared to 2015. Increased development
activity and significant well productivity improvements drove
substantial volume increases in the Delaware Basin, with additional growth from
the Powder River and DJ Basins. These contributions were
offset by volume declines in the Bakken and Eagle Ford resulting
from lower activity levels. Natural gas liquids volumes grew
6 percent while natural gas volumes decreased 7 percent primarily
due to natural decline and the sale of the company's Barnett and
Haynesville Shale dry gas assets. Compared to the same prior
year period, lease and well expenses decreased 20 percent and
transportation expenses decreased 8 percent, both on a per-unit
basis. Total operating costs, which includes lease and well,
transportation, gathering and processing, and general and
administrative expenses, were down 15 percent year over year.
"EOG achieved near company-record returns on new capital in 2016
in spite of the lowest crude oil prices in 13 years," said William
R. "Bill" Thomas, Chairman and Chief Executive Officer.
"Through continued improvements in well productivity, cost
reductions and expanded resource potential, EOG is positioned to
excel as crude oil prices continue to recover. More than
ever, EOG continues to lead the industry through its innovative
technology and disciplined culture."
2017 Capital Plan
EOG's 2017 plan is designed to
maximize returns and grow crude oil volumes while maintaining a
strong balance sheet through disciplined spending. EOG
expects to grow total company crude oil volumes by 18 percent,
assuming investment and dividend payments within cash flow at a
$50 average oil price.
Capital expenditures for 2017 are expected to range from
$3.7 to $4.1 billion, including
production facilities and gathering, processing and other
expenditures, and excluding acquisitions. The company expects
to complete approximately 480 net wells in 2017, compared to 445
net wells in 2016. EOG anticipates flat to lower completed
well costs in 2017 versus 2016 levels as continued efficiencies and
service contract expirations are expected to offset potential cost
increases.
Capital will be allocated primarily to EOG's highest
rate-of-return oil assets in the Eagle Ford, Delaware Basin, Rockies and the Bakken.
After reducing the drilled uncompleted well inventory to a normal
operating level in 2016, the company will increase its focus on its
6,000 remaining premium drilling locations. EOG is capable of
delivering very strong rates of return in the current commodity
price environment through premium drilling combined with the
company's expectations that well costs will remain flat or lower in
2017. Premium inventory includes wells with a direct
after-tax rate of return of at least 30 percent assuming
$40 flat crude oil prices.
"EOG's goal during the last two years was to exit the industry
downturn in better shape than when we entered it," Thomas
said. "We clearly accomplished that goal with spectacular
improvements in all facets of the business. We made major
technology advances in our proprietary well targeting, completion
designs, drilling practices and production operations. EOG is
now set to resume strong oil growth within cash flow."
Delaware Basin
In the
fourth quarter 2016, EOG continued active development of its
world-class position in the Delaware Basin. EOG integrated
the assets acquired in the Yates transaction and further optimized
its proprietary well targeting methods across its expanded position
of 416,000 net acres.
EOG completed 17 wells in the Delaware Basin Wolfcamp in the fourth quarter
with an average treated lateral length of 4,900 feet per well and
average 30-day initial production rates per well of 2,405 barrels
of oil equivalent per day (Boed), or 1,595 Bopd, 365 barrels per
day (Bpd) of natural gas liquids (NGLs) and 2.7 million cubic feet
per day (MMcfd) of natural gas. In Lea County, N.M., EOG completed the Endurance
36 State Com #705H and #706H with an average treated lateral length
of 7,000 feet per well and average 30-day initial production rates
per well of 2,495 Bopd, 505 Bpd of NGLs and 3.7 MMcfd of natural
gas.
In the Delaware Basin Bone
Spring, EOG completed three wells in the fourth quarter with an
average treated lateral length of 4,400 feet per well and average
30-day initial production rates per well of 1,680 Boed, or 1,280
Bopd, 180 Bpd of NGLs and 1.3 MMcfd of natural gas. In
Lea County, N.M., EOG completed
the Della 29 Fed Com #602H with a treated lateral of 4,500 feet and
30-day initial production rates of 1,905 Bopd, 225 Bpd of NGLs and
1.7 MMcfd of natural gas. This well is six miles north of
EOG's next closest Bone Spring well.
In the Delaware Basin Leonard,
EOG completed eight wells in the fourth quarter with an average
treated lateral length of 4,600 feet per well and average 30-day
initial production rates per well of 1,745 Boed, or 985 Bopd, 345
Bpd of NGLs and 2.5 MMcfd of natural gas. In Lea County, N.M., EOG completed the Leghorn 32
State #201H with a treated lateral of 4,500 feet and 30-day initial
production rates of 2,550 Bopd, 480 Bpd of NGLs and 3.6 MMcfd of
natural gas. This well is 12 miles north of EOG's next
closest Leonard well.
South Texas Eagle Ford
EOG continued to achieve strong
well results and efficiencies in the South Texas Eagle Ford in the
fourth quarter 2016. For the full year 2016, crude oil
production declined just 8 percent year-over-year, despite a 28
percent reduction in the number of well completions.
In the fourth quarter, EOG completed 75 wells in the Eagle Ford
with an average treated lateral length of 5,700 feet per well and
average 30-day initial production rates per well of 1,190 Boed, or
990 Bopd, 85 Bpd of NGLs and 0.7 MMcfd of natural gas. The
fourth quarter 2016 completions in the Eagle Ford included 45 wells
that were drilled prior to 2016.
South Texas Austin Chalk
EOG continued to test its
position in the South Texas Austin Chalk, which lies above the
South Texas Eagle Ford. In the fourth quarter, EOG completed
nine wells in the Austin Chalk with an average treated lateral
length of 4,100 feet per well and average 30-day initial production
rates per well of 1,975 Boed, or 1,475 Bopd, 220 Bpd of NGLs and
1.7 MMcfd of natural gas.
Rockies and the Bakken
During the fourth quarter, EOG
significantly reduced its inventory of drilled uncompleted wells in
the Rockies and the
Bakken.
In the Powder River Basin, EOG completed three wells in the
fourth quarter with average 30-day initial production rates per
well of 2,155 Boed, or 1,810 Bopd, 135 Bpd of NGLs and 1.3 MMcfd of
natural gas.
In the North Dakota Bakken, EOG completed 34 wells in the fourth
quarter with average 30-day initial production rates per well of
820 Boed, or 715 Bopd, 55 Bpd of NGLs and 0.3 MMcfd of natural gas.
The fourth quarter 2016 completions in the Bakken included 31
wells that were drilled prior to 2016.
Reserves
At year-end 2016, total company net proved
reserves were 2,147 million barrels of oil equivalent (MMBoe),
comprised of 55 percent crude oil and condensate, 19 percent NGLs
and 26 percent natural gas. Net proved reserve additions from
all sources excluding revisions due to price replaced 163 percent
of EOG's 2016 production at a finding and development cost of
$5.22 per barrel of oil
equivalent. Revisions due to price reduced net proved
reserves by 101 MMBoe and asset divestitures decreased net proved
reserves by 168 MMBoe. Total company net proved reserves
increased 1.4 percent in 2016 as proved reserve additions from
drilling activities and revisions other than price offset the
impact of asset divestitures and declines in commodity
prices. (For more reserves detail and a reconciliation of
non-GAAP measures to GAAP measures, please refer to the attached
tables.)
For the 29th consecutive year, internal reserves
estimates were within 5 percent of estimates independently prepared
by DeGolyer and MacNaughton.
Hedging Activity
For the period January 1 through June 30, 2017, EOG has crude
oil financial price swap contracts in place for 35,000 Bopd at a
weighted average price of $50.04 per
barrel.
For the period March 1 through November
30, 2017, EOG has natural gas financial price swap contracts
in place for 30,000 million British thermal units (MMBtu) per day
at a weighted average price of $3.10
per MMBtu. For the period March 1
through November 30, 2018, EOG has natural gas financial
price swap contracts in place for 35,000 MMBtu per day at a
weighted average price of $3.00 per
MMBtu.
For the period March 1 through November
30, 2017, EOG sold natural gas call option contracts for
213,750 MMBtu per day at an average strike price of $3.44 per MMBtu. For the period
March 1 through November 30, 2018,
EOG sold natural gas call option contracts for 120,000 MMBtu per
day at an average strike price of $3.38 per MMBtu.
For the period March 1 through November
30, 2017, EOG purchased natural gas put option contracts for
171,000 MMBtu per day at an average strike price of $2.92 per MMBtu. For the period
March 1 through November 30, 2018,
EOG purchased natural gas put option contracts for 96,000 MMBtu per
day at an average strike price of $2.94 per MMBtu.
For the period March 1 through November
30, 2017, EOG has natural gas collar contracts for 80,000
MMBtu per day at an average ceiling price of $3.69 per MMBtu and an average floor price of
$3.20 per MMBtu.
A comprehensive summary of crude oil and natural gas derivative
contracts is provided in the attached tables.
Capital Structure and Asset Sales
At December 31, 2016, EOG's total debt outstanding
was $7.0 billion with a debt-to-total
capitalization ratio of 33 percent. Considering cash on the balance
sheet of $1.6 billion at the end of
the fourth quarter, EOG's net debt was $5.4
billion with a net debt-to-total capitalization ratio of 28
percent. For a reconciliation of non-GAAP measures to GAAP
measures, please refer to the attached tables.
Proceeds from asset sales for the full year 2016 totaled
$1.1 billion, which includes
$662 million of proceeds from sales
made during the fourth quarter 2016. Associated production of
the divested assets in 2016 at the time of each respective sale was
an aggregate 220 MMcfd of natural gas, 4,000 Bopd and 8,800 Bpd of
NGLs (this was partially offset by the full year impact of acquired
production from the Yates transaction of 2,900 Bopd, 150 Bpd of
NGLs and 20 MMcfd of natural gas).
Dividend
The board of directors declared a dividend of
$0.1675 per share on EOG's Common
Stock, payable April 28, 2017, to
stockholders of record as of April
13, 2017. The indicated annual rate is $0.67 per share.
Conference Call February 28,
2017
EOG's fourth quarter and full year 2016 results
conference call will be available via live audio webcast at
9 a.m. Central time (10 a.m. Eastern time) on Tuesday, February 28, 2017. To access the
live audio webcast and related presentation materials, log on to
the Investors Overview page on the EOG website at
http://investors.eogresources.com/overview.
EOG Resources, Inc. is one of the largest independent
(non-integrated) crude oil and natural gas companies in
the United States with proved
reserves in the United States,
Trinidad, the United Kingdom and China. EOG Resources, Inc. is listed on
the New York Stock Exchange and is traded under the ticker symbol
"EOG." For additional information about EOG, please visit
www.eogresources.com.
This press release includes forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements, other than statements of historical
facts, including, among others, statements and projections
regarding EOG's future financial position, operations, performance,
business strategy, returns, budgets, reserves, levels of
production, costs and asset sales, statements regarding future
commodity prices and statements regarding the plans and objectives
of EOG's management for future operations, are forward-looking
statements. EOG typically uses words such as "expect,"
"anticipate," "estimate," "project," "strategy," "intend," "plan,"
"target," "goal," "may," "will," "should" and "believe" or the
negative of those terms or other variations or comparable
terminology to identify its forward-looking statements. In
particular, statements, express or implied, concerning EOG's future
operating results and returns or EOG's ability to replace or
increase reserves, increase production, reduce or otherwise control
operating and capital costs, generate income or cash flows or pay
dividends are forward-looking statements. Forward-looking
statements are not guarantees of performance. Although EOG
believes the expectations reflected in its forward-looking
statements are reasonable and are based on reasonable assumptions,
no assurance can be given that these assumptions are accurate or
that any of these expectations will be achieved (in full or at all)
or will prove to have been correct. Moreover, EOG's
forward-looking statements may be affected by known, unknown or
currently unforeseen risks, events or circumstances that may be
outside EOG's control. Important factors that could cause
EOG's actual results to differ materially from the expectations
reflected in EOG's forward-looking statements include, among
others:
- the timing, extent and duration of changes in prices for,
supplies of, and demand for, crude oil and condensate, natural gas
liquids, natural gas and related commodities;
- the extent to which EOG is successful in its efforts to acquire
or discover additional reserves;
- the extent to which EOG is successful in its efforts to
economically develop its acreage in, produce reserves and achieve
anticipated production levels from, and maximize reserve recovery
from, its existing and future crude oil and natural gas exploration
and development projects;
- the extent to which EOG is successful in its efforts to market
its crude oil and condensate, natural gas liquids, natural gas and
related commodity production;
- the availability, proximity and capacity of, and costs
associated with, appropriate gathering, processing, compression,
transportation and refining facilities;
- the availability, cost, terms and timing of issuance or
execution of, and competition for, mineral licenses and leases and
governmental and other permits and rights-of-way, and EOG's ability
to retain mineral licenses and leases;
- the impact of, and changes in, government policies, laws and
regulations, including tax laws and regulations; environmental,
health and safety laws and regulations relating to air emissions,
disposal of produced water, drilling fluids and other wastes,
hydraulic fracturing and access to and use of water; laws and
regulations imposing conditions or restrictions on drilling and
completion operations and on the transportation of crude oil and
natural gas; laws and regulations with respect to derivatives and
hedging activities; and laws and regulations with respect to the
import and export of crude oil, natural gas and related
commodities;
- EOG's ability to effectively integrate acquired crude oil and
natural gas properties into its operations, fully identify existing
and potential problems with respect to such properties and
accurately estimate reserves, production and costs with respect to
such properties;
- the extent to which EOG's third-party-operated crude oil and
natural gas properties are operated successfully and
economically;
- competition in the oil and gas exploration and production
industry for the acquisition of licenses, leases and properties,
employees and other personnel, facilities, equipment, materials and
services;
- the availability and cost of employees and other personnel,
facilities, equipment, materials (such as water) and services;
- the accuracy of reserve estimates, which by their nature
involve the exercise of professional judgment and may therefore be
imprecise;
- weather, including its impact on crude oil and natural gas
demand, and weather-related delays in drilling and in the
installation and operation (by EOG or third parties) of production,
gathering, processing, refining, compression and transportation
facilities;
- the ability of EOG's customers and other contractual
counterparties to satisfy their obligations to EOG and, related
thereto, to access the credit and capital markets to obtain
financing needed to satisfy their obligations to EOG;
- EOG's ability to access the commercial paper market and other
credit and capital markets to obtain financing on terms it deems
acceptable, if at all, and to otherwise satisfy its capital
expenditure requirements;
- the extent to which EOG is successful in its completion of
planned asset dispositions;
- the extent and effect of any hedging activities engaged in by
EOG;
- the timing and extent of changes in foreign currency exchange
rates, interest rates, inflation rates, global and domestic
financial market conditions and global and domestic general
economic conditions;
- political conditions and developments around the world (such as
political instability and armed conflict), including in the areas
in which EOG operates;
- the use of competing energy sources and the development of
alternative energy sources;
- the extent to which EOG incurs uninsured losses and liabilities
or losses and liabilities in excess of its insurance coverage;
- acts of war and terrorism and responses to these acts;
- physical, electronic and cyber security breaches; and
- the other factors described under ITEM 1A, Risk Factors, on
pages 13 through 22 of EOG's Annual Report on Form 10-K for the
fiscal year ended December 31, 2016,
and any updates to those factors set forth in EOG's subsequent
Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
In light of these risks, uncertainties and assumptions, the
events anticipated by EOG's forward-looking statements may not
occur, and, if any of such events do, we may not have anticipated
the timing of their occurrence or the duration and extent of their
impact on our actual results. Accordingly, you should not
place any undue reliance on any of EOG's forward-looking
statements. EOG's forward-looking statements speak only as of the
date made, and EOG undertakes no obligation, other than as required
by applicable law, to update or revise its forward-looking
statements, whether as a result of new information, subsequent
events, anticipated or unanticipated circumstances or
otherwise.
The United States Securities and Exchange Commission (SEC)
permits oil and gas companies, in their filings with the SEC, to
disclose not only "proved" reserves (i.e., quantities of oil and
gas that are estimated to be recoverable with a high degree of
confidence), but also "probable" reserves (i.e., quantities of oil
and gas that are as likely as not to be recovered) as well as
"possible" reserves (i.e., additional quantities of oil and gas
that might be recovered, but with a lower probability than probable
reserves). Statements of reserves are only estimates and may
not correspond to the ultimate quantities of oil and gas recovered.
Any reserve estimates provided in this press release that are not
specifically designated as being estimates of proved reserves may
include "potential" reserves and/or other estimated reserves not
necessarily calculated in accordance with, or contemplated by, the
SEC's latest reserve reporting guidelines. Investors are
urged to consider closely the disclosure in EOG's Annual Report on
Form 10-K for the fiscal year ended December
31, 2016, available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor
Relations). You can also obtain this report from the SEC by calling
1-800-SEC-0330 or from the SEC's website at www.sec.gov. In
addition, reconciliation and calculation schedules for non-GAAP
financial measures can be found on the EOG website at
www.eogresources.com.
For Further
Information Contact:
|
Investors
|
|
Cedric W.
Burgher
|
|
(713)
571-4658
|
|
David J.
Streit
|
|
(713)
571-4902
|
|
W. John
Wagner
|
|
(713)
571-4404
|
|
|
|
Media and
Investors
|
|
Kimberly M.
Ehmer
|
|
(713)
571-4676
|
EOG RESOURCES,
INC.
|
Financial
Report
|
(Unaudited; in
millions, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Operating
Revenues
|
$
|
2,402.0
|
|
$
|
1,796.8
|
|
$
|
7,650.6
|
|
$
|
8,757.4
|
Net Loss
|
$
|
(142.4)
|
|
$
|
(284.3)
|
|
$
|
(1,096.7)
|
|
$
|
(4,524.5)
|
Net Loss Per
Share
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.25)
|
|
$
|
(0.52)
|
|
$
|
(1.98)
|
|
$
|
(8.29)
|
Diluted
|
$
|
(0.25)
|
|
$
|
(0.52)
|
|
$
|
(1.98)
|
|
$
|
(8.29)
|
Average Number of
Common Shares
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
567.3
|
|
|
546.4
|
|
|
553.4
|
|
|
545.7
|
Diluted
|
|
567.3
|
|
|
546.4
|
|
|
553.4
|
|
|
545.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary Income
Statements
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Net Operating
Revenues
|
|
|
|
|
|
|
|
Crude Oil
and Condensate
|
$
|
1,366,223
|
|
$
|
1,040,470
|
|
$
|
4,317,341
|
|
$
|
4,934,562
|
Natural
Gas Liquids
|
|
137,849
|
|
|
96,521
|
|
|
437,250
|
|
|
407,658
|
Natural
Gas
|
|
215,373
|
|
|
217,381
|
|
|
742,152
|
|
|
1,061,038
|
Gains
(Losses) on Mark-to-Market Commodity
Derivative Contracts
|
|
(65,787)
|
|
|
4,970
|
|
|
(99,608)
|
|
|
61,924
|
Gathering,
Processing and Marketing
|
|
614,594
|
|
|
432,292
|
|
|
1,966,259
|
|
|
2,253,135
|
Gains
(Losses) on Asset Dispositions, Net
|
|
104,034
|
|
|
(3,656)
|
|
|
205,835
|
|
|
(8,798)
|
Other,
Net
|
|
29,753
|
|
|
8,783
|
|
|
81,403
|
|
|
47,909
|
Total
|
|
2,402,039
|
|
|
1,796,761
|
|
|
7,650,632
|
|
|
8,757,428
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
Lease and
Well
|
|
241,846
|
|
|
247,916
|
|
|
927,452
|
|
|
1,182,282
|
Transportation Costs
|
|
193,319
|
|
|
207,580
|
|
|
764,106
|
|
|
849,319
|
Gathering
and Processing Costs
|
|
32,516
|
|
|
39,653
|
|
|
122,901
|
|
|
146,156
|
Exploration Costs
|
|
39,110
|
|
|
34,946
|
|
|
124,953
|
|
|
149,494
|
Dry Hole
Costs
|
|
193
|
|
|
429
|
|
|
10,657
|
|
|
14,746
|
Impairments
|
|
297,946
|
|
|
168,171
|
|
|
620,267
|
|
|
6,613,546
|
Marketing
Costs
|
|
634,248
|
|
|
461,848
|
|
|
2,007,635
|
|
|
2,385,982
|
Depreciation, Depletion and Amortization
|
|
862,524
|
|
|
769,457
|
|
|
3,553,417
|
|
|
3,313,644
|
General
and Administrative
|
|
102,182
|
|
|
109,014
|
|
|
394,815
|
|
|
366,594
|
Taxes
Other Than Income
|
|
103,642
|
|
|
87,500
|
|
|
349,710
|
|
|
421,744
|
Total
|
|
2,507,526
|
|
|
2,126,514
|
|
|
8,875,913
|
|
|
15,443,507
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Loss
|
|
(105,487)
|
|
|
(329,753)
|
|
|
(1,225,281)
|
|
|
(6,686,079)
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (Expense)
Income, Net
|
|
(17,198)
|
|
|
(6,080)
|
|
|
(50,543)
|
|
|
1,916
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss Before Interest
Expense and Income Taxes
|
|
(122,685)
|
|
|
(335,833)
|
|
|
(1,275,824)
|
|
|
(6,684,163)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
71,325
|
|
|
62,993
|
|
|
281,681
|
|
|
237,393
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss Before Income
Taxes
|
|
(194,010)
|
|
|
(398,826)
|
|
|
(1,557,505)
|
|
|
(6,921,556)
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax
Benefit
|
|
(51,658)
|
|
|
(114,530)
|
|
|
(460,819)
|
|
|
(2,397,041)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Loss
|
$
|
(142,352)
|
|
$
|
(284,296)
|
|
$
|
(1,096,686)
|
|
$
|
(4,524,515)
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared
per Common Share
|
$
|
0.1675
|
|
$
|
0.1675
|
|
$
|
0.6700
|
|
$
|
0.6700
|
EOG RESOURCES,
INC.
|
Operating
Highlights
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Wellhead Volumes
and Prices
|
|
|
|
Crude Oil and
Condensate Volumes (MBbld) (A)
|
|
|
|
United
States
|
|
306.0
|
|
|
279.9
|
|
|
278.3
|
|
|
283.3
|
Trinidad
|
|
0.9
|
|
|
0.9
|
|
|
0.8
|
|
|
0.9
|
Other International
(B)
|
|
4.8
|
|
|
0.2
|
|
|
3.4
|
|
|
0.2
|
Total
|
|
311.7
|
|
|
281.0
|
|
|
282.5
|
|
|
284.4
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Crude Oil and
Condensate Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
47.93
|
|
$
|
40.34
|
|
$
|
41.84
|
|
$
|
47.55
|
Trinidad
|
|
40.04
|
|
|
32.38
|
|
|
33.76
|
|
|
39.51
|
Other International
(B)
|
|
38.96
|
|
|
53.28
|
|
|
36.72
|
|
|
57.32
|
Composite
|
|
47.76
|
|
|
40.32
|
|
|
41.76
|
|
|
47.53
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids
Volumes (MBbld) (A)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
80.9
|
|
|
79.1
|
|
|
81.6
|
|
|
76.9
|
Other International
(B)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.1
|
Total
|
|
80.9
|
|
|
79.1
|
|
|
81.6
|
|
|
77.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Liquids Prices ($/Bbl) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
18.51
|
|
$
|
13.25
|
|
$
|
14.63
|
|
$
|
14.50
|
Other International
(B)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
4.61
|
Composite
|
|
18.51
|
|
|
13.25
|
|
|
14.63
|
|
|
14.49
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd) (A)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
800
|
|
|
860
|
|
|
810
|
|
|
886
|
Trinidad
|
|
323
|
|
|
370
|
|
|
340
|
|
|
349
|
Other International
(B)
|
|
22
|
|
|
27
|
|
|
25
|
|
|
30
|
Total
|
|
1,145
|
|
|
1,257
|
|
|
1,175
|
|
|
1,265
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas
Prices ($/Mcf) (C)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$
|
2.05
|
|
$
|
1.44
|
|
$
|
1.60
|
|
$
|
1.97
|
Trinidad
|
|
1.89
|
|
|
2.57
|
|
|
1.88
|
|
|
2.89
|
Other International
(B)
|
|
3.85
|
|
|
6.51
|
|
|
3.64
|
|
|
5.05
|
Composite
|
|
2.04
|
|
|
1.88
|
|
|
1.73
|
|
|
2.30
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent
Volumes (MBoed) (D)
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
520.3
|
|
|
502.2
|
|
|
494.9
|
|
|
507.9
|
Trinidad
|
|
54.6
|
|
|
62.7
|
|
|
57.5
|
|
|
59.1
|
Other International
(B)
|
|
8.6
|
|
|
4.6
|
|
|
7.6
|
|
|
5.2
|
Total
|
|
583.5
|
|
|
569.5
|
|
|
560.0
|
|
|
572.2
|
|
|
|
|
|
|
|
|
|
|
|
|
Total MMBoe
(D)
|
|
53.7
|
|
|
52.4
|
|
|
205.0
|
|
|
208.9
|
|
|
|
|
|
|
|
|
|
|
|
|
(A) Thousand barrels
per day or million cubic feet per day, as applicable.
|
(B) Other
International includes EOG's United Kingdom, China, Canada and
Argentina operations. The Argentina operations were sold in
the third quarter of 2016.
|
(C) Dollars per
barrel or per thousand cubic feet, as applicable. Excludes
the impact of financial commodity derivative
instruments.
|
(D) Thousand barrels
of oil equivalent per day or million barrels of oil equivalent, as
applicable; includes crude oil and condensate, natural gas liquids
and natural gas. Crude oil equivalent volumes are determined
using a ratio of 1.0 barrel of crude oil and condensate or natural
gas liquids to 6.0 thousand cubic feet of natural gas. MMBoe
is calculated by multiplying the MBoed amount by the number of days
in the period and then dividing that amount by one
thousand.
|
EOG RESOURCES,
INC.
|
Summary Balance
Sheets
|
(Unaudited; in
thousands, except share data)
|
|
|
|
|
|
|
|
December
31,
|
|
December
31,
|
|
2016
|
|
2015
|
ASSETS
|
Current
Assets
|
|
|
|
|
|
Cash and Cash
Equivalents
|
$
|
1,599,895
|
|
$
|
718,506
|
Accounts Receivable,
Net
|
|
1,216,320
|
|
|
930,610
|
Inventories
|
|
350,017
|
|
|
598,935
|
Income Taxes
Receivable
|
|
12,305
|
|
|
40,704
|
Deferred Income
Taxes
|
|
169,387
|
|
|
147,812
|
Other
|
|
206,679
|
|
|
155,677
|
Total
|
|
3,554,603
|
|
|
2,592,244
|
|
|
|
|
|
|
Property, Plant
and Equipment
|
|
|
|
|
|
Oil and Gas Properties
(Successful Efforts Method)
|
|
49,592,091
|
|
|
50,613,241
|
Other Property, Plant and
Equipment
|
|
4,008,564
|
|
|
3,986,610
|
Total Property, Plant and Equipment
|
|
53,600,655
|
|
|
54,599,851
|
Less: Accumulated
Depreciation, Depletion and Amortization
|
|
(27,893,577)
|
|
|
(30,389,130)
|
Total Property, Plant and Equipment, Net
|
|
25,707,078
|
|
|
24,210,721
|
Other
Assets
|
|
197,752
|
|
|
167,505
|
Total
Assets
|
$
|
29,459,433
|
|
$
|
26,970,470
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS' EQUITY
|
Current
Liabilities
|
|
|
|
|
|
Accounts Payable
|
$
|
1,511,826
|
|
$
|
1,471,953
|
Accrued Taxes
Payable
|
|
118,411
|
|
|
93,618
|
Dividends Payable
|
|
96,120
|
|
|
91,546
|
Liabilities from Price Risk
Management Activities
|
|
61,817
|
|
|
-
|
Current Portion of Long-Term
Debt
|
|
6,579
|
|
|
6,579
|
Other
|
|
232,538
|
|
|
155,591
|
Total
|
|
2,027,291
|
|
|
1,819,287
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term
Debt
|
|
6,979,779
|
|
|
6,648,911
|
Other
Liabilities
|
|
1,282,142
|
|
|
971,335
|
Deferred Income
Taxes
|
|
5,188,640
|
|
|
4,587,902
|
Commitments and
Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'
Equity
|
|
|
|
|
|
Common Stock, $0.01 Par,
640,000,000 Shares Authorized and
576,950,272
Shares and 550,150,823 Shares Issued at December 31,
2016 and 2015,
respectively
|
|
205,770
|
|
|
205,502
|
Additional Paid in
Capital
|
|
5,420,385
|
|
|
2,923,461
|
Accumulated Other
Comprehensive Loss
|
|
(19,010)
|
|
|
(33,338)
|
Retained Earnings
|
|
8,398,118
|
|
|
9,870,816
|
Common Stock Held in
Treasury, 250,155 Shares and 292,179 Shares at
December 31, 2016 and
2015, respectively
|
|
(23,682)
|
|
|
(23,406)
|
Total Stockholders' Equity
|
|
13,981,581
|
|
|
12,943,035
|
Total Liabilities
and Stockholders' Equity
|
$
|
29,459,433
|
|
$
|
26,970,470
|
EOG RESOURCES,
INC.
|
Summary Statements
of Cash Flows
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
Twelve Months
Ended
|
|
December
31,
|
|
2016
|
|
2015
|
Cash Flows from
Operating Activities
|
|
|
|
|
|
Reconciliation of Net
Loss to Net Cash Provided by Operating Activities:
|
|
|
|
|
|
Net Loss
|
$
|
(1,096,686)
|
|
$
|
(4,524,515)
|
Items Not Requiring
(Providing) Cash
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
3,553,417
|
|
|
3,313,644
|
Impairments
|
|
620,267
|
|
|
6,613,546
|
Stock-Based Compensation Expenses
|
|
128,090
|
|
|
130,577
|
Deferred Income Taxes
|
|
(515,206)
|
|
|
(2,482,307)
|
(Gains) Losses on Asset Dispositions, Net
|
|
(205,835)
|
|
|
8,798
|
Other, Net
|
|
61,690
|
|
|
11,896
|
Dry Hole Costs
|
|
10,657
|
|
|
14,746
|
Mark-to-Market Commodity
Derivative Contracts
|
|
|
|
|
|
Total Losses (Gains)
|
|
99,608
|
|
|
(61,924)
|
Net Cash (Payments for) Received from Settlements of Commodity
Derivative Contracts
|
|
(22,219)
|
|
|
730,114
|
Excess Tax Benefits from
Stock-Based Compensation
|
|
(29,357)
|
|
|
(26,058)
|
Other, Net
|
|
10,971
|
|
|
12,532
|
Changes in Components of
Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
Accounts Receivable
|
|
(232,799)
|
|
|
641,412
|
Inventories
|
|
170,694
|
|
|
58,450
|
Accounts Payable
|
|
(74,048)
|
|
|
(1,409,197)
|
Accrued Taxes Payable
|
|
92,782
|
|
|
11,798
|
Other Assets
|
|
(40,636)
|
|
|
118,143
|
Other Liabilities
|
|
(16,225)
|
|
|
(66,257)
|
Changes in Components of
Working Capital Associated with Investing and Financing
Activities
|
|
(156,102)
|
|
|
499,767
|
Net Cash Provided
by Operating Activities
|
|
2,359,063
|
|
|
3,595,165
|
|
|
|
|
|
|
Investing Cash
Flows
|
|
|
|
|
|
Additions to Oil and Gas
Properties
|
|
(2,489,756)
|
|
|
(4,725,150)
|
Additions to Other Property,
Plant and Equipment
|
|
(93,039)
|
|
|
(288,013)
|
Proceeds from Sales of
Assets
|
|
1,119,215
|
|
|
192,807
|
Net Cash Received from Yates
Acquisition
|
|
54,534
|
|
|
-
|
Changes in Components of
Working Capital Associated with Investing Activities
|
|
156,102
|
|
|
(499,900)
|
Net Cash Used in
Investing Activities
|
|
(1,252,944)
|
|
|
(5,320,256)
|
|
|
|
|
|
|
Financing Cash
Flows
|
|
|
|
|
|
Net Commercial Paper
(Repayments) Borrowings
|
|
(259,718)
|
|
|
259,718
|
Long-Term Debt
Borrowings
|
|
991,097
|
|
|
990,225
|
Long-Term Debt
Repayments
|
|
(563,829)
|
|
|
(500,000)
|
Dividends Paid
|
|
(372,845)
|
|
|
(367,005)
|
Excess Tax Benefits from
Stock-Based Compensation
|
|
29,357
|
|
|
26,058
|
Treasury Stock
Purchased
|
|
(82,125)
|
|
|
(48,791)
|
Proceeds from Stock Options
Exercised and Employee Stock Purchase Plan
|
|
23,296
|
|
|
22,690
|
Debt Issuance
Costs
|
|
(1,602)
|
|
|
(5,951)
|
Repayment of Capital Lease
Obligation
|
|
(6,353)
|
|
|
(6,156)
|
Other, Net
|
|
-
|
|
|
133
|
Net Cash (Used in)
Provided by Financing Activities
|
|
(242,722)
|
|
|
370,921
|
|
|
|
|
|
|
Effect of Exchange
Rate Changes on Cash
|
|
17,992
|
|
|
(14,537)
|
|
|
|
|
|
|
Increase
(Decrease) in Cash and Cash Equivalents
|
|
881,389
|
|
|
(1,368,707)
|
Cash and Cash
Equivalents at Beginning of Period
|
|
718,506
|
|
|
2,087,213
|
Cash and Cash
Equivalents at End of Period
|
$
|
1,599,895
|
|
$
|
718,506
|
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Adjusted Net Income (Loss)
(Non-GAAP)
|
To Net Loss
(GAAP)
|
(Unaudited; in
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month and twelve-month periods ended December 31,
2016 and 2015 reported Net Loss (GAAP) to reflect actual net cash
received from (payments for) settlements of commodity derivative
contracts by eliminating the unrealized mark-to-market (gains)
losses from these transactions, to eliminate the net (gains) losses
on asset dispositions in 2016 and 2015, to add back impairment
charges related to certain of EOG's assets in 2016 and 2015,
to add back an early leasehold termination payment as the result of
a legal settlement in 2015, to eliminate the impact of the Texas
margin tax rate reduction in 2015, to add back severance costs
associated with EOG's North American operations in 2015, to
eliminate the impact of the Trinidad tax settlement in 2016, to add
back certain voluntary retirement expense in 2016, and to add back
acquisition costs and state apportionment change related to the
Yates transaction in 2016. EOG believes this presentation may
be useful to investors who follow the practice of some industry
analysts who adjust reported company earnings to match hedge
realizations to production settlement months and make certain other
adjustments to exclude non-recurring items. EOG management
uses this information for purposes of comparing its financial
performance with the financial performance of other companies in
the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Three Months
Ended
|
|
December 31,
2016
|
|
December 31,
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
|
Diluted
|
|
|
|
Income
|
|
|
|
Diluted
|
|
Before
|
|
Tax
|
|
After
|
|
Earnings
|
|
Before
|
|
Tax
|
|
After
|
|
Earnings
|
|
Tax
|
|
Impact
|
|
Tax
|
|
per
Share
|
|
Tax
|
|
Impact
|
|
Tax
|
|
per
Share
|
Reported Net Loss
(GAAP)
|
$
(194,010)
|
|
$
51,658
|
|
$
(142,352)
|
|
$
(0.25)
|
|
$
(398,826)
|
|
$
114,530
|
|
$
(284,296)
|
|
$
(0.52)
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gains) Losses on
Mark-to-Market Commodity
Derivative Contracts
|
65,787
|
|
(23,583)
|
|
42,204
|
|
0.07
|
|
(4,970)
|
|
1,772
|
|
(3,198)
|
|
(0.01)
|
Net Cash Received
from Settlements of
Commodity Derivative Contracts
|
-
|
|
29
|
|
29
|
|
-
|
|
69,093
|
|
(24,632)
|
|
44,461
|
|
0.08
|
Add: Net (Gains)
Losses on Asset Dispositions
|
(104,034)
|
|
36,856
|
|
(67,178)
|
|
(0.12)
|
|
3,656
|
|
(735)
|
|
2,921
|
|
0.01
|
Add:
Impairments
|
217,839
|
|
(76,728)
|
|
141,111
|
|
0.25
|
|
94,484
|
|
(16,335)
|
|
78,149
|
|
0.15
|
Add: Legal
Settlement - Early Leasehold Termination
|
-
|
|
-
|
|
-
|
|
-
|
|
19,355
|
|
(6,900)
|
|
12,455
|
|
0.02
|
Add: Voluntary
Retirement Expense
|
-
|
|
(57)
|
|
(57)
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
Add:
Acquisition - State Apportionment Change
|
-
|
|
16,424
|
|
16,424
|
|
0.03
|
|
-
|
|
-
|
|
-
|
|
-
|
Add:
Acquisition Costs
|
2,173
|
|
955
|
|
3,128
|
|
0.01
|
|
-
|
|
-
|
|
-
|
|
-
|
Adjustments to Net
Income (Loss)
|
181,765
|
|
(46,104)
|
|
135,661
|
|
0.24
|
|
181,618
|
|
(46,830)
|
|
134,788
|
|
0.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Loss) (Non-GAAP)
|
$
(12,245)
|
|
$
5,554
|
|
$
(6,691)
|
|
$
(0.01)
|
|
$
(217,208)
|
|
$
67,700
|
|
$
(149,508)
|
|
$
(0.27)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
567,337
|
|
|
|
|
|
|
|
546,432
|
Diluted
|
|
|
|
|
|
|
567,337
|
|
|
|
|
|
|
|
546,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
567,337
|
|
|
|
|
|
|
|
546,432
|
Diluted
|
|
|
|
|
|
|
567,337
|
|
|
|
|
|
|
|
546,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months
Ended
|
|
Twelve Months
Ended
|
|
December 31,
2016
|
|
December 31,
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
|
|
|
|
Diluted
|
|
|
|
Income
|
|
|
|
Diluted
|
|
Before
|
|
Tax
|
|
After
|
|
Earnings
|
|
Before
|
|
Tax
|
|
After
|
|
Earnings
|
|
Tax
|
|
Impact
|
|
Tax
|
|
per
Share
|
|
Tax
|
|
Impact
|
|
Tax
|
|
per
Share
|
Reported Net Loss
(GAAP)
|
$(1,557,505)
|
|
$460,819
|
|
$(1,096,686)
|
|
$
(1.98)
|
|
$(6,921,556)
|
|
$2,397,041
|
|
$(4,524,515)
|
|
$
(8.29)
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Gains) Losses on
Mark-to-Market Commodity
Derivative Contracts
|
99,608
|
|
(35,640)
|
|
63,968
|
|
0.12
|
|
(61,924)
|
|
22,076
|
|
(39,848)
|
|
(0.07)
|
Net Cash Received
from (Payments for)
Settlements of Commodity Derivative
Contracts
|
(22,219)
|
|
7,950
|
|
(14,269)
|
|
(0.03)
|
|
730,114
|
|
(260,286)
|
|
469,828
|
|
0.86
|
Add: Net (Gains)
Losses on Asset Dispositions
|
(205,835)
|
|
61,491
|
|
(144,344)
|
|
(0.26)
|
|
8,798
|
|
(4,183)
|
|
4,615
|
|
0.01
|
Add:
Impairments
|
320,617
|
|
(113,368)
|
|
207,249
|
|
0.37
|
|
6,307,592
|
|
(2,182,220)
|
|
4,125,372
|
|
7.56
|
Add: Legal
Settlement - Early Leasehold Termination
|
-
|
|
-
|
|
-
|
|
-
|
|
19,355
|
|
(6,900)
|
|
12,455
|
|
0.02
|
Less: Texas Margin
Tax Rate Reduction
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(19,500)
|
|
(19,500)
|
|
(0.04)
|
Add: Severance
Costs
|
-
|
|
-
|
|
-
|
|
-
|
|
8,505
|
|
(3,032)
|
|
5,473
|
|
0.01
|
Add: Trinidad
Tax Settlement
|
-
|
|
43,000
|
|
43,000
|
|
0.08
|
|
-
|
|
-
|
|
-
|
|
-
|
Add: Voluntary
Retirement Expense
|
42,054
|
|
(15,047)
|
|
27,007
|
|
0.05
|
|
-
|
|
-
|
|
-
|
|
-
|
Add:
Acquisition - State Apportionment Change
|
-
|
|
16,424
|
|
16,424
|
|
0.03
|
|
-
|
|
-
|
|
-
|
|
-
|
Add:
Acquisition Costs
|
5,100
|
|
(88)
|
|
5,012
|
|
0.01
|
|
-
|
|
-
|
|
-
|
|
-
|
Adjustments to Net
Income (Loss)
|
239,325
|
|
(35,278)
|
|
204,047
|
|
0.37
|
|
7,012,440
|
|
(2,454,045)
|
|
4,558,395
|
|
8.35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Net
Income (Loss) (Non-GAAP)
|
$(1,318,180)
|
|
$425,541
|
|
$
(892,639)
|
|
$
(1.61)
|
|
$
90,884
|
|
$
(57,004)
|
|
$
33,880
|
|
$
0.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
553,384
|
|
|
|
|
|
|
|
545,697
|
Diluted
|
|
|
|
|
|
|
553,384
|
|
|
|
|
|
|
|
545,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Number of
Common Shares (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
553,384
|
|
|
|
|
|
|
|
545,697
|
Diluted
|
|
|
|
|
|
|
553,384
|
|
|
|
|
|
|
|
549,610
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Discretionary Cash Flow (Non-GAAP)
|
To Net Cash Provided By
Operating Activities (GAAP)
|
(Unaudited; in
thousands)
|
|
The following chart
reconciles the three-month and twelve-month periods ended December
31, 2016 and 2015 Net Cash Provided by Operating Activities (GAAP)
to Discretionary Cash Flow (Non-GAAP). EOG believes this
presentation may be useful to investors who follow the practice of
some industry analysts who adjust Net Cash Provided by Operating
Activities for Exploration Costs (excluding Stock-Based
Compensation Expenses), Excess Tax Benefits from Stock-Based
Compensation, Changes in Components of Working Capital and Other
Assets and Liabilities, and Changes in Components of Working
Capital Associated with Investing and Financing Activities.
EOG management uses this information for comparative purposes
within the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
|
December
31,
|
|
December
31,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by
Operating Activities (GAAP)
|
$
|
804,745
|
|
$
|
615,813
|
|
$
|
2,359,063
|
|
$
|
3,595,165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration Costs
(excluding Stock-Based Compensation Expenses)
|
|
|
33,931
|
|
|
28,758
|
|
|
104,199
|
|
|
124,011
|
Excess Tax Benefits
from Stock-Based Compensation
|
|
|
7,286
|
|
|
1,839
|
|
|
29,357
|
|
|
26,058
|
Changes in Components
of Working Capital and Other Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
and
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
Receivable
|
|
|
220,939
|
|
|
(193,101)
|
|
|
232,799
|
|
|
(641,412)
|
Inventories
|
|
|
(33,131)
|
|
|
(31,443)
|
|
|
(170,694)
|
|
|
(58,450)
|
Accounts
Payable
|
|
|
(127,165)
|
|
|
98,986
|
|
|
74,048
|
|
|
1,409,197
|
Accrued Taxes
Payable
|
|
|
21,214
|
|
|
65,777
|
|
|
(92,782)
|
|
|
(11,798)
|
Other
Assets
|
|
|
28,110
|
|
|
28,822
|
|
|
40,636
|
|
|
(118,143)
|
Other
Liabilities
|
|
|
53,024
|
|
|
50,574
|
|
|
16,225
|
|
|
66,257
|
Changes in Components
of Working Capital Associated with Investing and Financing
Activities
|
|
|
36,342
|
|
|
19,436
|
|
|
156,102
|
|
|
(499,767)
|
|
Discretionary Cash
Flow (Non-GAAP)
|
|
$
|
1,045,295
|
|
$
|
685,461
|
|
$
|
2,748,953
|
|
$
|
3,891,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash
Flow (Non-GAAP) - Percentage Increase/Decrease
|
|
|
52%
|
|
|
|
|
|
-29%
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Adjusted Earnings Before Interest
Expense,
|
Income Taxes,
Depreciation, Depletion and Amortization, Exploration
Costs,
|
Dry Hole Costs,
Impairments and Additional Items (Adjusted EBITDAX)
|
(Non-GAAP)
to Net Loss (GAAP)
|
(Unaudited; in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
adjusts the three-month and twelve-month periods ended December 31,
2016 and 2015 reported Net Loss (GAAP) to Earnings Before Interest
Expense, Income
Taxes (Income Tax Benefit), Depreciation, Depletion
and Amortization, Exploration Costs, Dry Hole Costs and Impairments
(EBITDAX) (Non-GAAP) and further adjusts such amount to reflect
actual net cash received from (payments for) settlements of
commodity derivative contracts by eliminating the unrealized
mark-to-market (MTM) (gains) losses from these transactions and to
eliminate the net (gains) losses on asset dispositions. EOG
believes this presentation may be useful to investors who follow
the practice of some industry analysts who adjust reported Net
Income (Loss) (GAAP) to add back Interest Expense, Income Taxes
(Income Tax Benefit), Depreciation, Depletion and Amortization,
Exploration Costs, Dry Hole Costs and Impairments and further
adjust such amount to match realizations to production settlement
months and make certain other adjustments to exclude non-recurring
and certain other items. EOG management uses this information
for purposes of comparing its financial performance with the
financial performance of other companies in the
industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Twelve Months
Ended
|
|
December
31,
|
|
December
31,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss
(GAAP)
|
$
|
(142,352)
|
|
$
|
(284,296)
|
|
$
|
(1,096,686)
|
|
$
|
(4,524,515)
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense,
Net
|
|
71,325
|
|
|
62,993
|
|
|
281,681
|
|
|
237,393
|
Income Tax
Benefit
|
|
(51,658)
|
|
|
(114,530)
|
|
|
(460,819)
|
|
|
(2,397,041)
|
Depreciation, Depletion and
Amortization
|
|
862,524
|
|
|
769,457
|
|
|
3,553,417
|
|
|
3,313,644
|
Exploration Costs
|
|
39,110
|
|
|
34,946
|
|
|
124,953
|
|
|
149,494
|
Dry Hole Costs
|
|
193
|
|
|
429
|
|
|
10,657
|
|
|
14,746
|
Impairments
|
|
297,946
|
|
|
168,171
|
|
|
620,267
|
|
|
6,613,546
|
EBITDAX (Non-GAAP)
|
|
1,077,088
|
|
|
637,170
|
|
|
3,033,470
|
|
|
3,407,267
|
Total (Gains) Losses on MTM
Commodity Derivative Contracts
|
|
65,787
|
|
|
(4,970)
|
|
|
99,608
|
|
|
(61,924)
|
Net Cash Received from
(Payments for) Settlements of Commodity Derivative
Contracts
|
|
-
|
|
|
69,093
|
|
|
(22,219)
|
|
|
730,114
|
(Gains) Losses on Asset
Dispositions, Net
|
|
(104,034)
|
|
|
3,656
|
|
|
(205,835)
|
|
|
8,798
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP)
|
$
|
1,038,841
|
|
$
|
704,949
|
|
$
|
2,905,024
|
|
$
|
4,084,255
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX
(Non-GAAP) - Percentage Increase/Decrease
|
|
47%
|
|
|
|
|
|
-29%
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Net Debt (Non-GAAP) and Total
|
Capitalization
(Non-GAAP) as Used in the Calculation of
|
the Net
Debt-to-Total Capitalization Ratio (Non-GAAP) to
|
Current and
Long-Term Debt (GAAP) and Total Capitalization
(GAAP)
|
(Unaudited; in
millions, except ratio data)
|
|
|
|
|
|
|
The following chart
reconciles Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP)
and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP),
as used in the Net Debt-to-Total Capitalization ratio
calculation. A portion of the cash is associated with
international subsidiaries; tax considerations may impact debt
paydown. EOG believes this presentation may be useful to
investors who follow the practice of some industry analysts who
utilize Net Debt and Total Capitalization (Non-GAAP) in their Net
Debt-to-Total Capitalization ratio calculation. EOG
management uses this information for comparative purposes within
the industry.
|
|
|
|
|
|
|
|
At
|
|
At
|
|
December
31,
|
|
December
31,
|
|
2016
|
|
2015
|
|
|
|
|
|
|
Total Stockholders'
Equity - (a)
|
$
|
13,982
|
|
$
|
12,943
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (b)
|
|
6,986
|
|
|
6,655
|
Less:
Cash
|
|
(1,600)
|
|
|
(719)
|
Net Debt (Non-GAAP) -
(c)
|
|
5,386
|
|
|
5,936
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (a) + (b)
|
$
|
20,968
|
|
$
|
19,598
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (a) + (c)
|
$
|
19,368
|
|
$
|
18,879
|
|
|
|
|
|
|
Debt-to-Total
Capitalization (GAAP) - (b) / [(a) + (b)]
|
|
33%
|
|
|
34%
|
|
|
|
|
|
|
Net Debt-to-Total
Capitalization (Non-GAAP) - (c) / [(a) + (c)]
|
|
28%
|
|
|
31%
|
EOG RESOURCES,
INC.
|
Reserves
Supplemental Data
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
2016 NET PROVED
RESERVES RECONCILIATION SUMMARY
|
|
|
|
|
|
|
|
United
|
|
|
|
Other
|
|
|
|
|
States
|
|
Trinidad
|
|
International
|
|
Total
|
|
CRUDE OIL &
CONDENSATE (MMBbl)
|
|
|
|
|
|
|
|
|
Beginning
Reserves
|
1,087.9
|
|
1.1
|
|
8.6
|
|
1,097.6
|
|
Revisions
|
42.0
|
|
-
|
|
0.9
|
|
42.9
|
|
Purchases in
place
|
25.8
|
|
-
|
|
-
|
|
25.8
|
|
Extensions,
discoveries and other additions
|
123.4
|
|
-
|
|
-
|
|
123.4
|
|
Sales in
place
|
(8.7)
|
|
-
|
|
-
|
|
(8.7)
|
|
Production
|
(101.9)
|
|
(0.3)
|
|
(1.2)
|
|
(103.4)
|
|
Ending
Reserves
|
1,168.5
|
|
0.8
|
|
8.3
|
|
1,177.6
|
|
|
NATURAL GAS
LIQUIDS (MMBbl)
|
|
|
|
|
|
|
|
|
Beginning
Reserves
|
382.9
|
|
-
|
|
-
|
|
382.9
|
|
Revisions
|
53.7
|
|
-
|
|
-
|
|
53.7
|
|
Purchases in
place
|
1.3
|
|
-
|
|
-
|
|
1.3
|
|
Extensions,
discoveries and other additions
|
41.9
|
|
-
|
|
-
|
|
41.9
|
|
Sales in
place
|
(33.5)
|
|
-
|
|
-
|
|
(33.5)
|
|
Production
|
(29.9)
|
|
-
|
|
-
|
|
(29.9)
|
|
Ending
Reserves
|
416.4
|
|
-
|
|
-
|
|
416.4
|
|
|
NATURAL GAS
(Bcf)
|
|
|
|
|
|
|
|
|
Beginning
Reserves
|
3,489.8
|
|
316.6
|
|
19.5
|
|
3,825.9
|
|
Revisions
|
298.4
|
|
29.5
|
|
5.2
|
|
333.1
|
|
Purchases in
place
|
91.5
|
|
-
|
|
-
|
|
91.5
|
|
Extensions,
discoveries and other additions
|
202.1
|
|
59.9
|
|
-
|
|
262.0
|
|
Sales in
place
|
(752.0)
|
|
-
|
|
-
|
|
(752.0)
|
|
Production
|
(308.6)
|
|
(125.1)
|
|
(8.9)
|
|
(442.6)
|
|
Ending
Reserves
|
3,021.2
|
|
280.9
|
|
15.8
|
|
3,317.9
|
|
|
OIL EQUIVALENTS
(MMBoe)
|
|
|
|
|
|
|
|
|
Beginning
Reserves
|
2,052.3
|
|
53.8
|
|
12.0
|
|
2,118.1
|
|
Revisions
|
145.5
|
|
5.0
|
|
1.7
|
|
152.2
|
|
Purchases in
place
|
42.3
|
|
-
|
|
-
|
|
42.3
|
|
Extensions,
discoveries and other additions
|
199.0
|
|
10.0
|
|
-
|
|
209.0
|
|
Sales in
place
|
(167.6)
|
|
-
|
|
-
|
|
(167.6)
|
|
Production
|
(183.2)
|
|
(21.1)
|
|
(2.8)
|
|
(207.1)
|
|
Ending
Reserves
|
2,088.3
|
|
47.7
|
|
10.9
|
|
2,146.9
|
|
|
Net Proved
Developed Reserves (MMBoe)
|
|
|
|
|
|
|
|
|
At December
31, 2015
|
1,018.5
|
|
50.7
|
|
3.3
|
|
1,072.5
|
|
At December
31, 2016
|
1,038.5
|
|
44.5
|
|
10.9
|
|
1,093.9
|
|
|
2016 EXPLORATION
AND DEVELOPMENT EXPENDITURES ($ Millions)
|
|
|
|
|
|
|
United
|
|
|
|
Other
|
|
|
|
|
States
|
|
Trinidad
|
|
International
|
|
Total
|
|
|
Acquisition Cost of
Unproved Properties
|
$3,216.6
|
|
$
-
|
|
$
-
|
|
$3,216.6
|
|
Exploration
Costs
|
156.3
|
|
2.7
|
|
6.8
|
|
165.8
|
|
Development
Costs
|
2,228.0
|
|
75.4
|
|
30.3
|
|
2,333.7
|
|
Total
Drilling
|
5,600.9
|
|
78.1
|
|
37.1
|
|
5,716.1
|
|
Acquisition Cost of
Proved Properties
|
749.0
|
|
-
|
|
-
|
|
749.0
|
|
Total Exploration
& Development Expenditures
|
6,349.9
|
|
78.1
|
|
37.1
|
|
6,465.1
|
|
Gathering, Processing
and Other
|
108.6
|
|
-
|
|
0.2
|
|
108.8
|
|
Asset Retirement
Costs
|
24.7
|
|
(3.2)
|
|
(41.4)
|
|
(19.9)
|
|
Total
Expenditures
|
6,483.2
|
|
74.9
|
|
(4.1)
|
|
6,554.0
|
|
Proceeds from Sales
in Place
|
(1,109.4)
|
|
-
|
|
(9.2)
|
|
(1,118.6)
|
|
Net
Expenditures
|
$5,373.8
|
|
$
74.9
|
|
$
(13.3)
|
|
$5,435.4
|
|
|
RESERVE
REPLACEMENT COSTS ($ / Boe ) *
|
|
|
|
|
|
|
|
|
All-in Total, Net
of Revisions
|
$
6.50
|
|
$
5.21
|
|
$
21.82
|
|
$
6.52
|
|
All-in Total,
Excluding Revisions Due to Price
|
$
5.14
|
|
$
6.05
|
|
$
21.82
|
|
$
5.22
|
|
|
RESERVE
REPLACEMENT *
|
|
|
|
|
|
|
|
|
Drilling
Only
|
109%
|
|
47%
|
|
0%
|
|
101%
|
|
All-in Total, Net
of Revisions & Dispositions
|
120%
|
|
71%
|
|
61%
|
|
114%
|
|
All-in Total,
Excluding Revisions Due to Price
|
176%
|
|
61%
|
|
61%
|
|
163%
|
|
All-in Total,
Liquids
|
187%
|
|
0%
|
|
75%
|
|
185%
|
|
|
*
See attached reconciliation schedule for calculation
methodology
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Total Exploration and Development Expenditures
(Non-GAAP)
|
As Used in the
Calculation of Reserve Replacement Costs ($ / BOE)
|
To Total Costs
Incurred in Exploration and Development Activities
(GAAP)
|
(Unaudited; in
millions, except ratio information)
|
|
|
|
|
|
|
|
|
|
The following chart
reconciles Total Costs Incurred in Exploration and Development
Activities (GAAP) to Total Exploration and Development Expenditures
(Non-GAAP), as used in the calculation of Reserve Replacement Costs
per Boe. There are numerous ways that industry participants
present Reserve Replacement Costs, including an "All-In"
calculation, which reflects total exploration and development
expenditures divided by total net proved reserve additions from all
sources. Combined with Reserve Replacement, these statistics
provide management and investors with an indication of the results
of the current year capital investment program. Reserve
Replacement Cost statistics are widely recognized and reported by
industry participants and are used by EOG management and other
third parties for comparative purposes within the industry.
Please note that the actual cost of adding reserves will vary from
the reported statistics due to timing differences in reserve
bookings and capital expenditures. Accordingly, some analysts
use three or five year averages of reported statistics, while
others prefer to estimate future costs. EOG has not included
future capital costs to develop proved undeveloped reserves in
exploration and development expenditures.
|
|
|
|
|
|
|
|
|
|
For the Twelve
Months Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United
|
|
|
|
Other
|
|
|
|
|
States
|
|
Trinidad
|
|
International
|
|
Total
|
|
|
Total Costs Incurred
in Exploration and Development Activities (GAAP)
|
$ 6,374.6
|
|
$
74.9
|
|
$
(4.3)
|
|
$
6,445.2
|
|
Less: Asset
Retirement Costs
|
(24.7)
|
|
3.2
|
|
41.4
|
|
19.9
|
|
Non-Cash Acquisition Costs of Unproved Properties
|
(3,101.8)
|
|
-
|
|
-
|
|
(3,101.8)
|
|
Non-Cash Acquisition Costs of Proved Properties
|
(732.3)
|
|
-
|
|
-
|
|
(732.3)
|
|
Total Exploration
& Development Expenditures (Non-GAAP) (a)
|
$
2,515.8
|
|
$
78.1
|
|
$
37.1
|
|
$
2,631.0
|
|
|
Total Expenditures
(GAAP)
|
$ 6,483.2
|
|
$
74.9
|
|
$
(4.1)
|
|
$
6,554.0
|
|
Less: Asset
Retirement Costs
|
(24.7)
|
|
3.2
|
|
41.4
|
|
19.9
|
|
Non-Cash Acquisition Costs of Unproved Properties
|
(3,101.8)
|
|
-
|
|
-
|
|
(3,101.8)
|
|
Non-Cash Acquisition Costs of Proved Properties
|
(732.3)
|
|
-
|
|
-
|
|
(732.3)
|
|
Non-Cash Acquisition Costs of Other Assets
|
(16.6)
|
|
-
|
|
-
|
|
(16.6)
|
|
Total Cash
Expenditures (Non-GAAP)
|
$
2,607.8
|
|
$
78.1
|
|
$
37.3
|
|
$
2,723.2
|
|
|
Net Proved Reserve
Additions From All Sources - Oil Equivalents
(MMBoe)
|
|
|
|
|
|
|
|
|
Revisions due to
price (b)
|
(102.8)
|
|
2.1
|
|
-
|
|
(100.7)
|
|
Revisions other than
price
|
248.3
|
|
2.9
|
|
1.7
|
|
252.9
|
|
Purchases in
place
|
42.3
|
|
-
|
|
-
|
|
42.3
|
|
Extensions,
discoveries and other additions (c)
|
199.0
|
|
10.0
|
|
-
|
|
209.0
|
|
Total Proved
Reserve Additions (d)
|
386.8
|
|
15.0
|
|
1.7
|
|
403.5
|
|
Sales in
place
|
(167.6)
|
|
-
|
|
-
|
|
(167.6)
|
|
Net Proved Reserve
Additions From All Sources (e)
|
219.2
|
|
15.0
|
|
1.7
|
|
235.9
|
|
|
Production
(f)
|
183.2
|
|
21.1
|
|
2.8
|
|
207.1
|
|
|
RESERVE
REPLACEMENT COSTS ($ / Boe)
|
|
|
|
|
|
|
|
|
All-in Total, Net
of Revisions (a / d)
|
$
6.50
|
|
$
5.21
|
|
$
21.82
|
|
$
6.52
|
|
All-in Total,
Excluding Revisions Due to Price (a / (d - b))
|
$
5.14
|
|
$
6.05
|
|
$
21.82
|
|
$
5.22
|
|
|
RESERVE
REPLACEMENT
|
|
|
|
|
|
|
|
|
Drilling Only (c /
f)
|
109%
|
|
47%
|
|
0%
|
|
101%
|
|
All-in Total, Net
of Revisions & Dispositions (e / f)
|
120%
|
|
71%
|
|
61%
|
|
114%
|
|
All-in Total,
Excluding Revisions Due to Price ((e - b ) /
f)
|
176%
|
|
61%
|
|
61%
|
|
163%
|
|
|
Net Proved Reserve
Additions From All Sources - Liquids (MMBbls)
|
|
|
|
|
|
|
|
|
Revisions
|
95.7
|
|
-
|
|
0.9
|
|
96.6
|
|
Purchases in
place
|
27.1
|
|
-
|
|
-
|
|
27.1
|
|
Extensions,
discoveries and other additions (g)
|
165.3
|
|
-
|
|
-
|
|
165.3
|
|
Total Proved
Reserve Additions
|
288.1
|
|
-
|
|
0.9
|
|
289.0
|
|
Sales in
place
|
(42.2)
|
|
-
|
|
-
|
|
(42.2)
|
|
Net Proved Reserve
Additions From All Sources (h)
|
245.9
|
|
-
|
|
0.9
|
|
246.8
|
|
|
Production
(i)
|
131.8
|
|
0.3
|
|
1.2
|
|
133.3
|
|
|
RESERVE
REPLACEMENT - LIQUIDS
|
|
|
|
|
|
|
|
|
Drilling Only (g /
i)
|
125%
|
|
0%
|
|
0%
|
|
124%
|
|
All-in Total, Net
of Revisions & Dispositions (h / i)
|
187%
|
|
0%
|
|
75%
|
|
185%
|
|
|
|
|
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of Drillbit Exploration and Development Expenditures
(Non-GAAP)
|
As Used in the
Calculation of Proved Developed Reserve Replacement Costs ($ /
BOE)
|
To Total Costs
Incurred in Exploration and Development Activities
(GAAP)
|
(Unaudited; in
millions, except ratio information)
|
|
|
|
|
|
|
|
|
|
The following chart
reconciles Total Costs Incurred in Exploration and Development
Activities (GAAP) to Drillbit Exploration and Development
Expenditures (Non-GAAP), as used in the calculation of Proved
Developed Reserve Replacement Costs per Boe. These statistics
provide management and investors with an indication of the results
of the current year capital investment program. Reserve
Replacement Cost statistics are widely recognized and reported by
industry participants and are used by EOG management and other
third parties for comparative purposes within the
industry.
|
|
|
|
|
|
|
|
|
|
For the Twelve
Months Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
PROVED DEVELOPED
RESERVE REPLACEMENT COSTS ($ / Boe)
|
|
|
|
|
|
|
|
|
Total Costs Incurred
in Exploration and Development Activities (GAAP)
|
|
|
|
|
|
|
$
6,445.2
|
|
Less: Asset
Retirement Costs
|
|
|
|
|
|
|
19.9
|
|
Acquisition Costs of Unproved Properties
|
|
|
|
|
|
|
(3,216.6)
|
|
Acquisition Cost of Proved Properties
|
|
|
|
|
|
|
(749.0)
|
|
Drillbit
Exploration & Development Expenditures (Non-GAAP)
(j)
|
|
|
|
|
|
|
$
2,499.5
|
|
|
Total Proved
Reserves - Extensions, discoveries and other additions
(MMBoe)
|
|
|
|
|
|
|
209.0
|
|
Add: Conversion of
proved undeveloped reserves to proved developed
|
|
|
|
|
|
|
149.2
|
|
Less: Proved
undeveloped extensions and discoveries
|
|
|
|
|
|
|
(138.1)
|
|
Proved Developed
Reserves - Extensions and discoveries (MMBoe)
|
|
|
|
|
|
|
220.1
|
|
|
Total Proved
Reserves - Revisions (MMBoe)
|
|
|
|
|
|
|
152.2
|
|
Less: Proved
Undeveloped Reserves - Revisions
|
|
|
|
|
|
|
(64.4)
|
|
Proved Developed - Revisions due to price
|
|
|
|
|
|
|
76.7
|
|
Proved Developed
Reserves - Revisions other than price (MMBoe)
|
|
|
|
|
|
|
164.5
|
|
|
Proved Developed
Reserves - Extensions and discoveries plus revisions
|
|
|
|
|
|
|
|
|
other
than price (MMBoe) (k)
|
|
|
|
|
|
|
384.6
|
|
|
|
|
|
|
|
|
|
|
Proved Developed
Reserve Replacement Cost Excluding Revisions Due to Price ($ / Boe)
(j / k)
|
|
|
|
$
6.50
|
|
EOG RESOURCES,
INC.
|
Crude Oil and
Natural Gas Financial
|
Commodity
Derivative Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG accounts for
financial commodity derivative contracts using the mark-to-market
accounting method. Presented below is a comprehensive summary
of EOG's crude oil price swap contracts through February 20, 2017,
with notional volumes expressed in Bbld and prices expressed in
$/Bbl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Price
Swap Contracts
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
(Bbld)
|
|
($/Bbl)
|
2016
|
|
|
|
|
|
|
|
|
|
|
April 12, 2016
through April 30, 2016 (closed)
|
|
|
|
|
90,000
|
|
$
42.30
|
May 1, 2016 through
June 30, 2016 (closed)
|
|
|
|
|
128,000
|
|
42.56
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
January 2017
(closed)
|
|
|
|
|
|
|
35,000
|
|
$
50.04
|
February 1, 2017
through June 30, 2017
|
|
|
|
|
35,000
|
|
50.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG has entered into
crude oil collar contracts, which establish ceiling and floor
prices for the sale of notional volumes of crude oil as specified
in the collar contracts. The collars require that EOG pay the
difference between the ceiling price and the average U.S. NYMEX
West Texas Intermediate crude oil price for the contract month
(Index Price) in the event the Index Price is above the ceiling
price. The collars grant EOG the right to receive the
difference between the floor price and the Index Price in the event
the Index Price is below the floor price. Presented below is
a comprehensive summary of EOG's crude oil collar contracts through
February 20, 2017, with notional volumes expressed in Bbld and
prices expressed in $/Bbl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Collar
Contracts
|
|
|
|
|
|
|
|
|
|
Weighted Average
Price ($/Bbl)
|
|
|
|
|
|
|
|
Volume
(Bbld)
|
|
Ceiling
Price
|
|
Floor
Price
|
2016
|
|
|
|
|
|
|
|
|
|
|
September 1, 2016
through December 31, 2016 (closed)
|
|
70,000
|
|
$
54.25
|
|
$
45.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented below is a
comprehensive summary of EOG's natural gas price swap contracts
through February 20, 2017, with notional volumes expressed in
MMBtud and prices expressed in $/MMBtu.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Price
Swap Contracts
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
|
|
|
|
(MMBtud)
|
|
($/MMBtu)
|
2016
|
|
|
|
|
|
|
|
|
|
|
March 1, 2016 through
August 31, 2016 (closed)
|
|
|
|
|
60,000
|
|
$
2.49
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
March 1, 2017 through
November 30, 2017
|
|
|
|
|
30,000
|
|
$
3.10
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
March 1, 2018 through
November 30, 2018
|
|
|
|
|
35,000
|
|
$
3.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG has sold call
options which establish a ceiling price for the sale of notional
volumes of natural gas as specified in the call option
contracts. The call options require that EOG pay the
difference between the call option strike price and either the
average or last business day NYMEX Henry Hub natural gas price for
the contract month (Henry Hub Index Price) in the event the Henry
Hub Index Price is above the call option strike price. In
addition, EOG has purchased put options which establish a floor
price for the sale of notional volumes of natural gas as specified
in the put option contracts. The put options grant EOG the
right to receive the difference between the put option strike price
and the Henry Hub Index Price in the event the Henry Hub Index
Price is below the put option strike price. Presented below
is a comprehensive summary of EOG's natural gas call and put option
contracts through February 20, 2017, with notional volumes
expressed in MMBtud and prices expressed in $/MMbtu.
|
|
Natural Gas Option
Contracts
|
|
|
|
|
|
Call Options
Sold
|
|
Put Options
Purchased
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
|
|
|
|
Volume
|
|
Average
Price
|
|
Volume
|
|
Average
Price
|
|
|
|
|
|
(MMBtud)
|
|
($/MMBtu)
|
|
(MMBtud)
|
|
($/MMBtu)
|
2016
|
|
|
|
|
|
|
|
|
|
|
September 2016
(closed)
|
|
|
56,250
|
|
$
3.46
|
|
-
|
|
$
-
|
October 1, 2016
through November 30, 2016 (closed)
|
|
|
106,250
|
|
3.48
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
March 1, 2017 through
November 30, 2017
|
|
|
213,750
|
|
$
3.44
|
|
171,000
|
|
$
2.92
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
March 1, 2018 through
November 30, 2018
|
|
|
120,000
|
|
$
3.38
|
|
96,000
|
|
$
2.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG has also entered
into natural gas collar contracts, which establish ceiling and
floor prices for the sale of notional volumes of natural gas as
specified in the collar contracts. The collars require that
EOG pay the difference between the ceiling price and the Henry Hub
Index Price in the event the Henry Hub Index Price is above the
ceiling price. The collars grant EOG the right to receive the
difference between the floor price and the Henry Hub Index Price in
the event the Henry Hub Index Price is below the floor price.
Presented below is a comprehensive summary of EOG's natural gas
collar contracts through February 20, 2017, with notional volumes
expressed in MMBtud and prices expressed in
$/MMbtu.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Collar
Contracts
|
|
|
|
|
|
|
|
|
|
Weighted Average
Price ($/MMbtu)
|
|
|
|
|
|
|
|
Volume
(MMBtud)
|
|
Ceiling
Price
|
|
Floor
Price
|
2017
|
|
|
|
|
|
|
|
|
|
|
March 1, 2017 through
November 30, 2017
|
|
|
|
|
80,000
|
|
$
3.69
|
|
$
3.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Definitions
|
|
|
|
|
|
|
|
|
|
|
Bbld
|
Barrels per
day
|
|
|
|
|
|
|
|
|
|
$/Bbl
|
Dollars per
barrel
|
|
|
|
|
|
|
|
|
|
MMBtud
|
Million British
thermal units per day
|
|
|
|
|
|
|
$/MMBtu
|
Dollars per million
British thermal units
|
|
|
|
|
|
|
NYMEX
|
New York Mercantile
Exchange
|
|
|
|
|
|
|
EOG RESOURCES,
INC.
|
Direct After-Tax
Rate of Return (ATROR)
|
|
The calculation of
our direct after-tax rate of return (ATROR) with respect to our
capital expenditure program for a particular play or well is based
on the estimated proved reserves ("net" to EOG's interest) for all
wells in such play or such well (as the case may be), the estimated
net present value (NPV) of the future net cash flows from such
reserves (for which we utilize certain assumptions regarding future
commodity prices and operating costs) and our direct net costs
incurred in drilling or acquiring (as the case may be) such wells
or well (as the case may be). As such, our direct ATROR with
respect to our capital expenditures for a particular play or well
cannot be calculated from our consolidated financial
statements.
|
|
|
Direct
ATROR
|
Based on Cash Flow
and Time Value of Money
|
- Estimated
future commodity prices and operating costs
|
- Costs
incurred to drill, complete and equip a well, including
facilities
|
Excludes Indirect
Capital
|
- Gathering
and Processing and other Midstream
|
- Land,
Seismic, Geological and Geophysical
|
|
Payback ~12 Months on
100% Direct ATROR Wells
|
First Five Years ~1/2
Estimated Ultimate Recovery Produced but ~3/4 of NPV
Captured
|
|
|
Return on Equity /
Return on Capital Employed
|
Based on GAAP Accrual
Accounting
|
Includes All Indirect
Capital and Growth Capital for Infrastructure
|
- Eagle Ford,
Bakken, Permian Facilities
|
- Gathering
and Processing
|
Includes Legacy Gas
Capital and Capital from Mature Wells
|
EOG RESOURCES,
INC.
|
Quantitative
Reconciliation of After-Tax Net Interest Expense (Non-GAAP),
Adjusted Net Income
|
(Non-GAAP), Net
Debt (Non-GAAP) and Total Capitalization (Non-GAAP) as used in the
Calculations of
|
Return on Capital
Employed (Non-GAAP) and Return on Equity (Non-GAAP) to Net Interest
Expense (GAAP),
|
Net Income (Loss)
(GAAP), Current and Long-Term Debt (GAAP) and Total Capitalization
(GAAP), Respectively
|
(Unaudited; in
millions, except ratio data)
|
|
|
|
|
|
|
|
|
|
|
|
|
The following chart
reconciles Net Interest Expense (GAAP), Net Income (Loss) (GAAP),
Current and Long-Term Debt (GAAP) and Total Capitalization (GAAP)
to After-Tax Net Interest Expense (Non-GAAP), Adjusted Net Income
(Non-GAAP), Net Debt (Non-GAAP) and Total Capitalization
(Non-GAAP), respectively, as used in the Return on Capital Employed
(ROCE) and Return on Equity (ROE) calculations. EOG believes
this presentation may be useful to investors who follow the
practice of some industry analysts who utilize After-Tax Net
Interest Expense, Adjusted Net Income, Net Debt and Total
Capitalization (Non-GAAP) in their ROCE and ROE calculations.
EOG management uses this information for purposes of comparing its
financial performance with the financial performance of other
companies in the industry.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
2013
|
Return on Capital
Employed (ROCE) (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Interest Expense
(GAAP)
|
$
|
282
|
|
$
|
237
|
|
$
|
201
|
|
|
|
Tax Benefit Imputed
(based on 35%)
|
|
(99)
|
|
|
(83)
|
|
|
(70)
|
|
|
|
After-Tax Net
Interest Expense (Non-GAAP) - (a)
|
$
|
183
|
|
$
|
154
|
|
$
|
131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
(GAAP) -
(b)
|
$
|
(1,097)
|
|
$
|
(4,525)
|
|
$
|
2,915
|
|
|
|
Adjustments to Net
Income (Loss), Net of Tax (See Accompanying Schedules)
|
204
|
(a)
|
|
4,559
|
(b)
|
|
(199)
|
(c)
|
|
|
Adjusted Net Income
(Non-GAAP) - (c)
|
$
|
(893)
|
|
$
|
34
|
|
$
|
2,716
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders'
Equity - (d)
|
$
|
13,982
|
|
$
|
12,943
|
|
$
|
17,713
|
|
$
|
15,418
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Stockholders' Equity * - (e)
|
$
|
13,463
|
|
$
|
15,328
|
|
$
|
16,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (f)
|
$
|
6,986
|
|
$
|
6,655
|
|
$
|
5,906
|
|
$
|
5,909
|
Less:
Cash
|
|
(1,600)
|
|
|
(719)
|
|
|
(2,087)
|
|
|
(1,318)
|
Net Debt (Non-GAAP) -
(g)
|
$
|
5,386
|
|
$
|
5,936
|
|
$
|
3,819
|
|
$
|
4,591
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (d) + (f)
|
$
|
20,968
|
|
$
|
19,598
|
|
$
|
23,619
|
|
$
|
21,327
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization
(Non-GAAP) - (d) + (g)
|
$
|
19,368
|
|
$
|
18,879
|
|
$
|
21,532
|
|
$
|
20,009
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Total
Capitalization (Non-GAAP) * - (h)
|
$
|
19,124
|
|
$
|
20,206
|
|
$
|
20,771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (GAAP Net
Income) - [(a) + (b)] /
(h)
|
|
-4.8%
|
|
|
-21.6%
|
|
|
14.7%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROCE (Non-GAAP
Adjusted Net Income) - [(a) + (c)] /
(h)
|
|
-3.7%
|
|
|
0.9%
|
|
|
13.7%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return on Equity
(ROE) (Non-GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (GAAP Net
Income) - (b) / (e)
|
|
-8.1%
|
|
|
-29.5%
|
|
|
17.6%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE (Non-GAAP
Adjusted Net Income) - (c) / (e)
|
|
-6.6%
|
|
|
0.2%
|
|
|
16.4%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* Average for the
current and immediately preceding year
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments to Net
Income (Loss) (GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) See below
schedule for detail of adjustments to Net Income (Loss) (GAAP) in
2016:
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2016
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
Adjustments:
|
|
|
|
|
|
|
|
|
Add: Mark-to-Market Commodity Derivative Contracts
Impact
|
$
|
77
|
|
$
|
(28)
|
|
$
|
49
|
Add: Impairments of Certain Assets
|
|
321
|
|
|
(113)
|
|
|
208
|
Less: Net Gains on Asset Dispositions
|
|
(206)
|
|
|
62
|
|
|
(144)
|
Add: Trinidad Tax Settlement
|
|
-
|
|
|
43
|
|
|
43
|
Add: Voluntary Retirement Expense
|
|
42
|
|
|
(15)
|
|
|
27
|
Add: Acquisition - State Apportionment
Change
|
|
-
|
|
|
16
|
|
|
16
|
Add: Acquisition Costs
|
|
5
|
|
|
-
|
|
|
5
|
Total
|
$
|
239
|
|
$
|
(35)
|
|
$
|
204
|
|
|
|
|
|
|
|
|
|
(b) See below
schedule for detail of adjustments to Net Income (Loss) (GAAP) in
2015:
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2015
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
Adjustments:
|
|
|
|
|
|
|
|
|
Add: Mark-to-Market Commodity Derivative Contracts
Impact
|
$
|
668
|
|
$
|
(238)
|
|
$
|
430
|
Add: Impairments of Certain Assets
|
|
6,308
|
|
|
(2,183)
|
|
|
4,125
|
Less: Texas Margin Tax Rate Reduction
|
|
-
|
|
|
(20)
|
|
|
(20)
|
Add: Legal Settlement - Early Leasehold
Termination
|
|
19
|
|
|
(6)
|
|
|
13
|
Add: Severance Costs
|
|
9
|
|
|
(3)
|
|
|
6
|
Add: Net Losses on Asset Dispositions
|
|
9
|
|
|
(4)
|
|
|
5
|
Total
|
$
|
7,013
|
|
$
|
(2,454)
|
|
$
|
4,559
|
|
|
|
|
|
|
|
|
|
(c) See below
schedule for detail of adjustments to Net Income (Loss) (GAAP) in
2014:
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2014
|
|
|
Before
|
|
|
Income
Tax
|
|
|
After
|
|
|
Tax
|
|
|
Impact
|
|
|
Tax
|
Adjustments:
|
|
|
|
|
|
|
|
|
Less: Mark-to-Market Commodity Derivative Contracts
Impact
|
$
|
(800)
|
|
$
|
285
|
|
$
|
(515)
|
Add: Impairments of Certain
Assets
|
|
824
|
|
|
(271)
|
|
|
553
|
Less: Net Gains on Asset Dispositions
|
|
(508)
|
|
|
21
|
|
|
(487)
|
Add: Tax Expense Related to the Repatriation
of Accumulated
Foreign Earnings in Future Years
|
|
-
|
|
|
250
|
|
|
250
|
Total
|
$
|
(484)
|
|
$
|
285
|
|
$
|
(199)
|
EOG RESOURCES,
INC.
|
First Quarter and
Full Year 2017 Forecast and Benchmark Commodity
Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) First Quarter and
Full Year 2017 Forecast
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The forecast items
for the first quarter and full year 2017 set forth below for EOG
Resources, Inc. (EOG) are based on current available information
and expectations as of the date of the accompanying press
release. EOG undertakes no obligation, other than as required
by applicable law, to update or revise this forecast, whether as a
result of new information, subsequent events, anticipated or
unanticipated circumstances or otherwise. This forecast,
which should be read in conjunction with the accompanying press
release and EOG's related Current Report on Form 8-K filing,
replaces and supersedes any previously issued guidance or
forecast.
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) Benchmark
Commodity Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG bases United
States and Trinidad crude oil and condensate price differentials
upon the West Texas Intermediate crude oil price at Cushing,
Oklahoma, using the simple average of the NYMEX settlement prices
for each trading day within the applicable calendar
month.
|
|
|
|
|
|
|
|
|
|
|
|
|
EOG bases United
States natural gas price differentials upon the natural gas price
at Henry Hub, Louisiana, using the simple average of the NYMEX
settlement prices for the last three trading days of the applicable
month.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Ranges
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
1Q 2017
|
|
|
Full Year
2017
|
Daily Sales
Volumes
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
Volumes (MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
300.0
|
-
|
|
310.0
|
|
|
320.0
|
-
|
|
335.0
|
Trinidad
|
|
0.3
|
-
|
|
0.5
|
|
|
0.3
|
-
|
|
0.5
|
Other International
|
|
2.0
|
-
|
|
4.0
|
|
|
4.0
|
-
|
|
7.0
|
Total
|
|
302.3
|
-
|
|
314.5
|
|
|
324.3
|
-
|
|
342.5
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids Volumes
(MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
72.0
|
-
|
|
78.0
|
|
|
72.0
|
-
|
|
82.0
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
670
|
-
|
|
710
|
|
|
725
|
-
|
|
760
|
Trinidad
|
|
300
|
-
|
|
330
|
|
|
275
|
-
|
|
315
|
Other International
|
|
18
|
-
|
|
24
|
|
|
25
|
-
|
|
30
|
Total
|
|
988
|
-
|
|
1,064
|
|
|
1,025
|
-
|
|
1,105
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Equivalent Volumes
(MBoed)
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
483.7
|
-
|
|
506.3
|
|
|
512.8
|
-
|
|
543.7
|
Trinidad
|
|
50.3
|
-
|
|
55.5
|
|
|
46.1
|
-
|
|
53.0
|
Other International
|
|
5.0
|
-
|
|
8.0
|
|
|
8.2
|
-
|
|
12.0
|
Total
|
|
539.0
|
-
|
|
569.8
|
|
|
567.1
|
-
|
|
608.7
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Costs
|
|
|
|
|
|
|
|
|
|
|
|
Unit Costs
($/Boe)
|
|
|
|
|
|
|
|
|
|
|
|
Lease and Well
|
$
|
4.60
|
-
|
$
|
5.00
|
|
$
|
4.30
|
-
|
$
|
5.00
|
Transportation Costs
|
$
|
3.40
|
-
|
$
|
4.00
|
|
$
|
3.10
|
-
|
$
|
3.90
|
Depreciation, Depletion and Amortization
|
$
|
15.80
|
-
|
$
|
16.10
|
|
$
|
15.50
|
-
|
$
|
16.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
($MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration, Dry Hole and
Impairment
|
$
|
95
|
-
|
$
|
125
|
|
$
|
415
|
-
|
$
|
465
|
General and
Administrative
|
$
|
90
|
-
|
$
|
100
|
|
$
|
365
|
-
|
$
|
395
|
Gathering and
Processing
|
$
|
28
|
-
|
$
|
30
|
|
$
|
105
|
-
|
$
|
125
|
Capitalized
Interest
|
$
|
7
|
-
|
$
|
8
|
|
$
|
25
|
-
|
$
|
30
|
Net Interest
|
$
|
69
|
-
|
$
|
71
|
|
$
|
273
|
-
|
$
|
283
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes Other Than
Income (% of Wellhead Revenue)
|
|
6.7%
|
-
|
|
7.1%
|
|
|
6.5%
|
-
|
|
6.9%
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
|
|
|
|
|
|
|
|
|
Effective
Rate
|
|
31%
|
-
|
|
36%
|
|
|
31%
|
-
|
|
36%
|
Current Taxes
($MM)
|
$
|
30
|
-
|
$
|
45
|
|
$
|
130
|
-
|
$
|
170
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
(Excluding Acquisitions, $MM)
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Development,
Excluding Facilities
|
|
|
|
|
|
|
$
|
3,000
|
-
|
$
|
3,350
|
Exploration and Development
Facilities
|
|
|
|
|
|
|
$
|
475
|
-
|
$
|
510
|
Gathering, Processing and
Other
|
|
|
|
|
|
|
$
|
225
|
-
|
$
|
240
|
|
|
|
|
|
|
|
|
|
|
|
|
Pricing - (Refer to
Benchmark Commodity Pricing in text)
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil and Condensate
($/Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) WTI
|
$
|
(2.00)
|
-
|
$
|
(1.00)
|
|
$
|
(2.50)
|
-
|
$
|
(0.50)
|
Trinidad - above (below) WTI
|
$
|
(9.75)
|
-
|
$
|
(7.75)
|
|
$
|
(9.50)
|
-
|
$
|
(7.50)
|
Other International - above (below) WTI
|
$
|
(10.00)
|
-
|
$
|
(8.00)
|
|
$
|
(3.00)
|
-
|
$
|
0.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
Liquids
|
|
|
|
|
|
|
|
|
|
|
|
Realizations as % of WTI
|
|
31%
|
-
|
|
35%
|
|
|
31%
|
-
|
|
35%
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
($/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
Differentials
|
|
|
|
|
|
|
|
|
|
|
|
United States - above (below) NYMEX Henry Hub
|
$
|
(1.10)
|
-
|
$
|
(0.70)
|
|
$
|
(1.15)
|
-
|
$
|
(0.65)
|
|
|
|
|
|
|
|
|
|
|
|
|
Realizations
|
|
|
|
|
|
|
|
|
|
|
|
Trinidad
|
$
|
2.00
|
-
|
$
|
2.40
|
|
$
|
1.90
|
-
|
$
|
2.50
|
Other International
|
$
|
3.75
|
-
|
$
|
4.25
|
|
$
|
3.50
|
-
|
$
|
4.50
|
|
|
|
|
|
|
|
|
|
|
|
|
Definitions
|
|
|
|
|
|
|
|
|
|
|
|
|
$/Bbl
|
U.S. Dollars per
barrel
|
|
|
|
|
|
|
|
|
|
|
|
$/Boe
|
U.S. Dollars per
barrel of oil equivalent
|
|
|
|
|
|
|
|
|
|
$/Mcf
|
U.S. Dollars per
thousand cubic feet
|
|
|
|
|
|
|
|
|
|
|
$MM
|
U.S. Dollars in
millions
|
|
|
|
|
|
|
|
|
|
|
|
MBbld
|
Thousand barrels per
day
|
|
|
|
|
|
|
|
|
|
|
|
MBoed
|
Thousand barrels of
oil equivalent per day
|
|
|
|
|
|
|
|
|
|
MMcfd
|
Million cubic feet
per day
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX
|
New York Mercantile
Exchange
|
|
|
|
|
|
|
|
|
|
|
|
WTI
|
West Texas
Intermediate
|
|
|
|
|
|
|
|
|
|
|
|
To view the original version on PR Newswire,
visit:http://www.prnewswire.com/news-releases/eog-resources-reports-fourth-quarter-and-full-year-2016-results-and-announces-2017-capital-program-300414269.html
SOURCE EOG Resources, Inc.